The present disclosure relates generally to methods and systems for performing wellsite operations. More particularly, this disclosure is directed to methods and systems for performing fracture and production operations, such as investigating subterranean formations and characterizing hydraulic fracture networks in a subterranean formation.
In order to facilitate the recovery of hydrocarbons from oil and gas wells, the subterranean formations surrounding such wells can be hydraulically fractured. Hydraulic fracturing may be used to create cracks in subsurface formations to allow oil or gas to move toward the well. A formation is fractured by introducing a specially engineered fluid (referred to as “fracturing fluid” or “fracturing slurry” herein) at high pressure and high flow rates into the formation through one or more wellbore. Hydraulic fractures may extend away from the wellbore hundreds of feet in two opposing directions according to the natural stresses within the formation. Under certain circumstances, they may form a complex fracture network.
The fracturing fluids may be loaded with proppants, which are sized particles that may be mixed with the fracturing fluid to help provide an efficient conduit for production of hydrocarbons to flow from the formation/reservoir to the wellbore. Proppant may comprise naturally occurring sand grains or gravel, man-made or specially engineered proppants, e.g. fibers, resin-coated sand, or high-strength ceramic materials, e.g. sintered bauxite. The proppant collects heterogeneously or homogenously inside the fracture to “prop” open the new cracks or pores in the formation. The proppant creates a plane of permeable conduits through which production fluids can flow to the wellbore. The fracturing fluids are preferably of high viscosity, and therefore capable of carrying effective volumes of proppant material. Fluid viscosity may vary with fluid temperature.
The fracturing fluid may be realized by a viscous fluid, sometimes referred to as “pad” that is injected into the treatment well at a rate and pressure sufficient to initiate and propagate a fracture in hydrocarbon formation. Injection of the “pad” is continued until a fracture of sufficient geometry is obtained to permit placement of the proppant particles. After the “pad,” the fracturing fluid may consist of a fracturing fluid and proppant material. The fracturing fluid may be gel, oil based, water based, brine, acid, emulsion, foam, or any other similar fluid. The fracturing fluid can contain several additives, viscosity builders, drag reducers, fluid-loss additives, corrosion inhibitors and the like. In order to keep the proppant suspended in the fracturing fluid until such time as all intervals of the formation have been fractured as desired, the proppant may have a density close to the density of the fracturing fluid utilized. Sometimes certain type of fibers may be used together with the proppant for various purposes, such as enhanced proppant-carrying, proppant segmenting, selective fracture growth, leakoff prevention, etc.
Proppants may be comprised of any of the various commercially available fused materials, such as silica or oxides. These fused materials can comprise any of the various commercially available glasses or high-strength ceramic products. Following the placement of the proppant, the well may be shut-in for a time sufficient to permit the pressure to bleed off into the formation or to permit the degradation of fibers, cross-linked gel or filter cake, depending on fluid temperature. The shut-in process causes the fracture to close and exert a closure stress on the propping agent particles. The shut-in period may vary from a few minutes to several days.
Current hydraulic fracture monitoring methods and systems may map where the fractures occur and the extent of the fractures. Some methods and systems of microseismic monitoring may process seismic event locations by mapping seismic arrival times and polarization information into three-dimensional space through the use of modeled travel times and/or ray paths. These methods and systems can be used to infer hydraulic fracture propagation over time.
Conventional hydraulic fracture models may also assume a bi-wing type induced fracture. These bi-wing fractures may be short in representing the complex nature of induced fractures in some unconventional reservoirs with preexisting natural fractures. Published models may map the complex geometry of discrete hydraulic fractures based on monitoring microseismic event distribution.
In some cases, models may be constrained by accounting for either the amount of pumped fluid or mechanical interactions both between fractures and injected fluid and among the fractures. Some of the constrained models may provide a fundamental understanding of involved mechanisms, but may be complex in mathematical description and/or require computer processing resources and time in order to provide accurate simulations of hydraulic fracture propagation.
Unconventional formations, such as shales, are being developed as reservoirs of hydrocarbon production. Once considered as source rocks and seals, shale formations are now considered as tight-porosity and low-permeability unconventional reservoirs. Hydraulic fracturing of shale formations may be used to stimulate and produce from the reservoir. The effectiveness and efficiency of a fracturing job may ultimately be judged by production from the stimulated reservoir.
Patterns of hydraulic fractures created by the fracturing stimulation may be complex and form a fracture network as indicated by the distribution of associated microseismic events. Models of complex hydraulic fracture networks (HFNs) have been developed to represent the created hydraulic fractures. Examples of fracture models are provided in U.S. Pat. Nos. 6,101,447, 7,363,162, 7,788,074, 8,498,852, 20080133186, 20100138196, and 20100250215.
Due to the complexity of HFNs, production from a stimulated shale reservoir may be numerically simulated. Numerical simulation for stimulation job design and post-job analysis may be time-consuming, and it may be inconvenient to construct a numerical model and carry out runs for each of the numerous designs of a stimulation job. Analytical solutions to HFN models and associated calculations for predicting fluid temperature or proppant transport are constantly sought to enhance stimulation job design and post-job analysis.